Apparatus and method for detecting pressure signals

ABSTRACT

An apparatus comprising an encoded pressure signal propagating in a fluid flowing in a conduit. An optical fiber measurement element has a reflector on one end and is disposed around at least a portion of the conduit. A light source injects a second optical signal and a third optical signal propagating in first and second optical fibers, respectively. A delay section is disposed in the second optical fiber. The second optical signal and the third optical signal are directed into the optical fiber measurement element and are reflected back from the reflective end such that at least a portion of the reflected second and third optical signals propagate through the second and first optical fibers respectively to an optical detector. The optical detector senses an interference between the reflected optical signals and outputs a first signal related thereto.

BACKGROUND OF THE INVENTION

The present disclosure relates generally to the field of telemetrysystems for transmitting information through a flowing fluid. Moreparticularly, the disclosure relates to the field of signal detection insuch a system.

Sensors may be positioned at the lower end of a well drilling stringwhich, while drilling is in progress, continuously or intermittentlymonitor predetermined drilling parameters and formation data andtransmit the information to a surface detector by some form oftelemetry. Such techniques are termed “measurement while drilling” orMWD. MWD may result in a major savings in drilling time and improve thequality of the well compared, for example, to conventional loggingtechniques. The MWD system may employ a system of telemetry in which thedata acquired by the sensors is transmitted to a receiver located on thesurface. Fluid signal telemetry is one of the most widely used telemetrysystems for MWD applications.

Fluid signal telemetry creates pressure signals in the drilling fluidthat is circulated under pressure through the drill string duringdrilling operations. The information that is acquired by the downholesensors is transmitted by suitably timing the formation of pressuresignals in the fluid stream. The pressure signals are commonly detectedby a pressure transducer tapped into a high pressure flow line at thesurface. Access to, and penetration of, the high pressure flow line maybe restricted due to operational and/or safety issues.

BRIEF DESCRIPTION OF THE DRAWINGS

A better understanding of the present invention can be obtained when thefollowing detailed description of example embodiments are considered inconjunction with the following drawings, in which:

FIG. 1 shows schematic example of a drilling system;

FIG. 2 shows an example block diagram of the acquisition of downholedata and the telemetry of such data to the surface in an exampledrilling operation;

FIGS. 3A-3D show examples of pressure signal transmitter assembliessuitable for use in a fluid telemetry system;

FIG. 4 shows an example embodiment of an optical interferometer systemused to detect downhole transmitted pressure signals;

FIG. 5 shows an example of a measurement section fiber adhered to apliant substrate;

FIG. 6 is a block diagram showing an example of the processing of areceived optical signal;

FIG. 7 is a chart of laboratory test data showing raw interferometerdata and integrated interferometer data compared to conventionalpressure sensor data for pressure signal detection;

FIG. 8 is shows an example of a modularized version of the opticalinterferometer system of FIG. 4;

FIG. 9 shows another embodiment of an optical interferometer system usedto detect downhole transmitted pressure signals; and

FIG. 10 shows an example of a modularized version of the opticalinterferometer system of FIG. 9.

While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings and will herein be described in detail. Itshould be understood, however, that the drawings and detaileddescription thereto are not intended to limit the invention to theparticular form disclosed, but on the contrary, the intention is tocover all modifications, equivalents and alternatives falling within thescope of the present invention as defined by the appended claims.

DETAILED DESCRIPTION

Referring to FIG. 1, a typical drilling installation is illustratedwhich includes a drilling derrick 10, constructed at the surface 12 ofthe well, supporting a drill string 14. The drill string 14 extendsthrough a rotary table 16 and into a borehole 18 that is being drilledthrough earth formations 20. The drill string 14 may include a kelly 22at its upper end, drill pipe 24 coupled to the kelly 22, and a bottomhole assembly 26 (BHA) coupled to the lower end of the drill pipe 24.The BHA 26 may include drill collars 28, an MWD tool 30, and a drill bit32 for penetrating through earth formations to create the borehole 18.In operation, the kelly 22, the drill pipe 24 and the BHA 26 may berotated by the rotary table 16. Alternatively, or in addition to therotation of the drill pipe 24 by the rotary table 16, the BHA 26 mayalso be rotated, as will be understood by one skilled in the art, by adownhole motor (not shown). The drill collars add weight to the drillbit 32 and stiffen the BHA 26, thereby enabling the BHA 26 to transmitweight to the drill bit 32 without buckling. The weight applied throughthe drill collars to the bit 32 permits the drill bit to crush theunderground formations.

As shown in FIG. 1, BHA 26 may include an MWD tool 30, which may be partof the drill collar section 28. As the drill bit 32 operates, drillingfluid (commonly referred to as “drilling mud”) may be pumped from a mudpit 34 at the surface by pump 15 through standpipe 11 and kelly hose 37,through drill string 14, indicated by arrow 5, to the drill bit 32. Thedrilling mud is discharged from the drill bit 32 and functions to cooland lubricate the drill bit, and to carry away earth cuttings made bythe bit. After flowing through the drill bit 32, the drilling fluidflows back to the surface through the annular area between the drillstring 14 and the borehole wall 19, indicated by arrow 6, where it iscollected and returned to the mud pit 34 for filtering. The circulatingcolumn of drilling mud flowing through the drill string may alsofunction as a medium for transmitting pressure signals 21 carryinginformation from the MWD tool 30 to the surface. In one embodiment, adownhole data signaling unit 35 is provided as part of MWD tool 30. Datasignaling unit 35 may include a pressure signal transmitter 100 forgenerating the pressure signals transmitted to the surface.

MWD tool 30 may include sensors 39 and 41, which may be coupled toappropriate data encoding circuitry, such as an encoder 38, whichsequentially produces encoded digital data electrical signalsrepresentative of the measurements obtained by sensors 39 and 41. Whiletwo sensors are shown, one skilled in the art will understand that asmaller or larger number of sensors may be used without departing fromthe principles of the present invention. The sensors 39 and 41 may beselected to measure downhole parameters including, but not limited to,environmental parameters, directional drilling parameters, and formationevaluation parameters. Such parameters may comprise downhole pressure,downhole temperature, the resistivity or conductivity of the drillingmud and earth formations, the density and porosity of the earthformations, as well as the orientation of the wellbore.

The MWD tool 30 may be located proximate to the bit 32. Datarepresenting sensor measurements of the parameters discussed may begenerated and stored in the MWD tool 30. Some or all of the data may betransmitted in the form of pressure signals by data signaling unit 35,through the drilling fluid in drill string 14. A pressure signaltravelling in the column of drilling fluid may be detected at thesurface by a signal detector unit 36 employing optical fiber loop 230.The detected signal may be decoded in controller 33. The pressuresignals may be encoded binary representations of measurement dataindicative of the downhole drilling parameters and formationcharacteristics measured by sensors 39 and 41. Controller 33 may belocated proximate the rig floor. Alternatively, controller 33 may belocated away from the rig floor. In one embodiment, controller 33 may beincorporated as part of a logging unit.

FIG. 2 shows a block diagram of the acquisition of downhole data and thetelemetry of such data to the surface in an example drilling operation.Sensors 39 and 41 acquire measurements related to the surroundingformation and/or downhole conditions and transmit them to encoder 38.Encoder 38 may have circuits 202 comprising analog circuits and analogto digital converters (A/D). Encoder 38 may also comprise a processor204 in data communication with a memory 206. Processor 204 actsaccording to programmed instructions to encode the data into digitalsignals according to a pre-programmed encoding technique. One skilled inthe art will appreciate that there are a number of encoding schemes thatmay be used for downhole telemetry. The chosen telemetry technique maydepend upon the type of pressure signal transmitter 100 used. Encoder 38outputs encoded data 208 to data signaling unit 35. Data signaling unit35 generates encoded pressure signals 21 that propagate through thedrilling fluid in drill string 14 to the surface. Pressure signals 21are detected at the surface by signal detector 36 and are transmitted tocontroller 33 for decoding. In one example embodiment, signal detector36 may be a fiber optic signal detector, described below. Controller 33may comprise interface circuitry 65 and a processor 66 for decodingpressure signals 21 into data 216. Data 216 may be output to a userinterface 218 and/or an information handling system such as logging unit221. Alternatively, in one embodiment, the controller circuitry andprocessor may be an integral part of the logging unit 221.

FIGS. 3A-3D show example embodiments of pressure signal transmitter 100.FIG. 3A shows a pressure signal transmitter 100 a disposed in datasignaling unit 35 a. Pressure signal transmitter 100 a has drillingfluid 5 flowing therethrough and comprises an actuator 105 that moves agate 110 back and forth against seat 115 allowing a portion of fluid 5to intermittently pass through opening 102 thereby generating a negativepressure signal 116 that propagates to the surface through drillingfluid 5.

FIG. 3B shows a pressure signal transmitter 100 b disposed in datasignaling unit 35 b. Pressure signal transmitter 100 b has drillingfluid 5 flowing therethrough and comprises an actuator 122 that moves apoppet 120 back and forth toward orifice 121 partially obstructing theflow of drilling fluid 5 thereby generating a positive pressure signal126 that propagates to the surface through drilling fluid 5.

FIG. 3C shows a pressure signal transmitter 100 c disposed in datasignaling unit 35 c. Pressure signal transmitter 100 c has drillingfluid 5 flowing therethrough and comprises an actuator 132 thatcontinuously rotates a rotor 130 in one direction relative to stator131. Stator 131 has flow passages 133 allowing fluid 5 to passtherethrough. Rotor 130 has flow passages 134 and the movement of flowpassages 134 past flow passages 133 of stator 131 generates a continuouswave pressure signal 136 that propagates to the surface through drillingfluid 5. Modulation of the continuous wave pressure signal may be usedto encode data therein. Modulation schemes may comprise frequencymodulation and phase shift modulation.

FIG. 3D shows a pressure signal transmitter 100 d disposed in datasignaling unit 35 d. Pressure signal transmitter 100 d has drillingfluid 5 flowing there through and comprises an actuator 142 that rotatesa rotor 140 back and forth relative to stator 141. Stator 141 has flowpassages 143 allowing fluid 5 to pass therethrough. Rotor 140 has flowpassages 144 and the alternating movement of flow passages 144 past theflow passages 143 of stator 141 generates a continuous wave pressuresignal 146 that propagates to the surface through drilling fluid 5.Modulation of the continuous wave pressure signal may be used to encodedata therein. Modulation schemes may comprise frequency modulation andphase shift modulation.

FIG. 4 shows an example of signal detector 36 comprising an opticalinterferometer 200 for detecting pressure signals in conduit 211.Interferometer 200 comprises a light source 202, an optical fiber loop230, an optical coupler/splitter 215, and an optical detector 210. It isnoted that optical coupler/splitter as used herein encompassesintegrated coupler splitters and individual couplers and splitters.Light source 202 may be a laser diode, a laser, or a light emittingdiode that emits light into optical coupler/splitter 215 where the lightis split into two beams 231 and 232. Beam 231 travels clockwise (CW)through loop 230, and beam 232 travels counter-clockwise (CCW) throughloop 230.

Loop 230 has a length, L, and comprises measurement section 220 anddelay section 225. In one embodiment, measurement section 220 may be2-10 meters in length. In this example, measurement section 220 iswrapped at least partially around conduit 211, which may be standpipe 11of FIG. 1. Alternatively, measurement section 220 may be wrapped aroundany section of flow conduit that has pressure signals travellingtherein. The length of measurement section 220 is designated by X inFIG. 4, and represents the length of fiber that reacts to hoop strainsin standpipe 11 caused by the pressure signals therein. The opticalfibers of measurement section 220 may be physically adhered to conduit211. Alternatively, see FIG. 5, measurement section 220 may comprise alength, X, of optical fiber 302 adhered in a folded pattern to a pliantsubstrate 300 that is attachable to a conduit. In one embodiment, pliantsubstrate 300 may be a biaxially-oriented polyethylene terephthalatematerial, for example a Mylar® material manufactured by E.I. Dupont deNemours & Co. Pliant substrate 300 may be adhesively attached, forexample, to standpipe 11 of FIG. 1 using any suitable adhesive, forexample an epoxy material or a cyanoacrylate material.

Delay section 225 may be on the order of 500-3000 meters in length. Thesmall diameter of optical fibers contemplated (on the order of 250 μm)allows such a length to be wound on a relatively small spool. As shownin FIG. 4, delay section 225 comprises a length identified as L−X. Itwill be seen that L is a factor in the sensitivity of the sensor.

Counter-propagating beams 231, 232 traverse loop 230 and recombinethrough coupler/splitter 215, and are detected by photo-detector 210.Under uniform (constant in time) conditions, beams 231, 232 willrecombine in phase at the detector 210 because they have both traveledequal distances around loop 230. Consider counter-propagating beams 231,232 and a time varying pressure P(t) in standpipe 11. Beams 231, 232will be in phase after they have traveled the distance X in their twopaths, and they will be in phase after they have continued through thedistance L−X as well. Now, let the pressure within the pipe be changingat a rate of dP/dt during the time Δt while beams 231, 232 travel thedistance L−X, then

Δt=(L−X)n/c,

where c is the speed of light, and n is the refractive index of theoptical fiber. During this time interval, the pressure within the pipechanges by an amount ΔP, which acts to radially expand standpipe 11.This expansion results in a change ΔX in the length, X, of themeasurement section 220 of optical fiber 230 wrapped around conduit 211.Although at the end of the interval Δt the two beams are in phase, theywill go out of phase for the last portion of the circuit before theyrecombine, because the length of measurement section 220 has changedduring the previous interval Δt. For the final leg of the trip aroundthe loop, the counter-clockwise beam 232 will travel a distance that isdifferent by an amount ΔX from the clockwise rotating beam 231. When thebeams combine at detector 210, they will be out of phase by a phasedifference, Δφ, where

Δφ=2π(ΔX)/nλ,

where λ is the wavelength of the light emitted by source 202. As beams231, 232 are combined, it can be shown that a factor in the signal willbe cos(Δφ/2). Thus, counter propagating beams 231, 232 will be out ofphase when ΔX=λ.

The change of the pressure in the pipe during the interval Δt is givenby

ΔP=(dP/dt)Δt=(dP/dt)(L−X)(n/c).

Let K be the sensitivity of the pipe to internal pressure; that is, thechange in circumference of the pipe ΔC due to a change in pressure ΔPgiven by,

ΔC=K(ΔP)

K can be computed from dimensions and material properties of the pipematerials. For example, for a thin-walled pipe, where D_(pipe)>10*pipethickness, t, it can be shown that

K=πD _(pipe) ²/2Et

where E is the modulus of elasticity of the pipe material.

For a thick walled pipe, where D_(pipe)≦10*pipe thickness, t, it can beshown that

K=2πD _(o) D _(i) ² /E(D ₀ ² −D _(i) ²)

where D_(o) and D, are the outer and inner pipe diameters, respectively.If N_(coil) is the number of turns of fiber around the pipe, then

ΔX=N(ΔC)=N _(coil) K(dP/dt)(L−X)(n/c).

Thus, the change in length indicated by the interferometer is a functionof the time derivative of the pressure signal, the number of turnsN_(coil) of fiber on the pipe, and the length L of the delay portion ofthe fiber.

FIG. 6 is a block diagram showing an example of the processing of areceived optical signal using interferometer 200. Counter propagatingbeams 231, 232 travel through optical fiber 230 comprising measurementsection 220 and delay section 225. In this example, delay section 225comprises multiple loops of optical fiber around a spool (not shown).Pressure signal 21 causes a lengthening of measurement section 220 whichproduces a phase shift in the recombined beams at detector 210, asdescribed previously. Detector 210 outputs a phase shift signal that isconditioned by signal conditioner 312 and outputs as an analog signalproportional to the time derivative of pressure dp/dt at 314. The signal314 is transmitted to A/D in block 316 where the dp/dt signal isdigitized. The digitized dp/dt signal is integrated in block 318 toproduce a digital signal similar to the original pressure signal P(t).The P(t) signal is then decoded in block 320 to produce data 216. Data216 may be used in log modules 324 to produce logs 326. In oneembodiment, optical source 202, optical detector 210, and signalconditioner 312 may be physically located close to conduit 211 in signaldetector 36. Alternatively, some of these items may be located away fromconduit 211, for example in controller 33. The functional modules 316,318, 320, 324, and 326 may comprise hardware and software and may belocated in controller 33. In one embodiment, controller 33 may be astand alone unit located in a separate location, for example a loggingunit. Alternatively, controller 33 may be an integral part of a loggingunit using shared hardware and software resources. While described abovewith reference to a single optical signal detector on a conduit, it isintended that the present disclosure cover any number of such detectorsspace out along such a conduit.

FIG. 7 is a chart of laboratory test data showing raw interferometerdata and integrated interferometer data compared to conventionalpressure sensor data for pressure signal detection. Pressure signals aregenerated in a flowing fluid in a flow loop. A pressure signaltransmitter generates pressure signals into the flowing fluid. Aninterferometer similar to interferometer 200 is installed on a sectionof conduit. A conventional strain gauge pressure sensor is mountedwithin 2 m of the interferometer. FIG. 7 shows the raw interferometerdata proportional to dp/dt in curve 700. The raw data is processed asdescribed above to produce an integrated interferometer curve 710. Curve705 is the reading from the conventional pressure transducer. As shownin FIG. 7, integrated interferometer curve 710 is substantially similarto conventional pressure transducer curve 705.

In one embodiment, an interferometer system, for example interferometersystem 200 described above, may be configured as shown in FIG. 8. Thesystem of FIG. 8 has been modularized by using commercially availableoptical connectors 810 to allow for the use of delay sections 225 ofvarying properties. For example, different delay modules 802 maycomprise delay sections 225 of different lengths as describedpreviously.

In another embodiment, FIG. 9 shows an embodiment of signal detector 936comprising an optical interferometer 900 for detecting pressure signalsin conduit 211. In this embodiment, light source 202 emits a lightsignal 930 into optical splitter/coupler 915 generating beam 931propagating through first fiber 921 and beam 932 propagating throughsecond fiber 922, having a delay section fiber 925 therein, to a secondoptical splitter/coupler 916. Beam 931, having taken the short path, L₁,through first fiber 921, enters and traverses the measurement section920 having length L₂, before the second beam 932. Second beam 932travels through the longer delay section 925, having length L₃. Beam 931experiences the strain induced by the pressure signal 21 passing throughthe section. Second beam 932 having gone through the delay section 925,enters the measurement section 920 at a later time than beam 931, andsenses the strain of the measurement section 925 during at a second timeafter the passage of the first beam 931. Measurement section fiber 920has a reflector 935 at its termination such that the signal beams 931,932 are reflected back toward the second splitter/coupler 916. Reflector935 may be a minor affixed to the end of the measurement section fiber920. Each of the reflected beams 931, 932 coming out of the measurementsection 920 will encounter the second splitter/coupler 916. Thereflected beams of interest travel through the alternate fiber sectionson the reverse path. That portion of first beam 931 which travelsthrough the second fiber 922 including delay section 925 on the returntrip, and that portion of the second beam 932 which travels throughfirst fiber 921, when recombined at first splitter/coupler 915, willhave each traversed substantially the same total optical path length,differing by the relatively small strain difference of the measurementsection during the passage of each beam. The combination of thesereflected beams will contain the phase information indicative of thetime derivative of the change in the length of the measurement sectioncaused by the passage of pressure signal 21. It is noted that other beampaths are possible. For example, a second combination of path lengthswould include beam 931 traversing straight down fibers 921 and 920 andreflecting back over the reverse path, resulting in a path length of2L₁+2L₂. Similarly, beam 932 may traverse down through second fiber 922,with delay section 925, and measurement section 920 and return throughthe same fibers, resulting in a path length of 2L₃+2L₂. The second fiberwith delay section 925 may be much greater in length than first fibersection 921. Therefore, there may be a substantial difference in pathlengths between the second combination and the desired measurementcombination of paths lengths. One skilled in the art of interferometricmeasurements will appreciate that the coherence length of the lightsource may be chosen, or adjusted, such that only the desired portionsof the reflected beams 931, 932 can be made to interfere at opticaldetector 210. For example, the coherence length is a function of theoptical source and the fiber characteristics. The coherence length is ameasure of the difference in path lengths of the two beams at whichinterference patterns may still be measured. By selecting, or adjusting,the optical source such that the coherence length is greater than thesmall difference in the desired measurement paths, but less than thedifference between the second path length combination, the interferencesignals from the second combination of paths may be substantiallyeliminated. The other possible path combinations may be similarlyeliminated from consideration.

FIG. 10 shows a modularized example of the system of FIG. 9. Forexample, available optical connectors 810 are inserted to allow for theuse of delay sections 225 of varying properties. For example, differentdelay modules 902 may comprise delay sections 225 of different lengthsas described previously.

Numerous variations and modifications will become apparent to thoseskilled in the art. It is intended that the following claims beinterpreted to embrace all such variations and modifications.

1. An apparatus comprising: an optical fiber measurement elementdisposed around at least a portion of a conduit; a reflector coupled toone end of the conduit; a light source injecting a first optical signalinto a first beam splitter/coupler to split the first optical signalinto a second optical signal propagating in a first optical fiber and athird optical signal propagating in a second optical fiber; a delaysection disposed in the second optical fiber; a second beamsplitter/coupler to combine and direct the second optical signal and thethird optical signal into the optical fiber measurement element to thereflector, the reflector reflecting the second optical signal and thethird optical signal back through the second beam splitter/coupler suchthat at least a portion of the reflected second optical signalpropagates through the second optical fiber and at least a portion ofthe third optical signals propagates through the first optical fiber;and an optical detector sensing an interference between the reflectedsecond optical signal and the reflected third optical signal caused byan encoded pressure signal propagating in a fluid flowing in the conduitand outputting a first signal related thereto.
 2. The apparatus of claim1 wherein the first signal is related to a time derivative of theencoded pressure signal in the conduit.
 3. The apparatus of claim 1wherein the reflective end comprises a mirror.
 4. The apparatus of claim1 further comprising a controller in data communication with the opticaldetector wherein the controller integrates the first signal with respectto time and generates an output signal substantially similar to thefluid pressure signal.
 5. The apparatus of claim 4 wherein thecontroller decodes the output signal into the data transmitted in theencoded pressure signal.
 6. The apparatus of claim 1 wherein the lightsource is chosen from the group consisting of a laser, a laser diode,and a light emitting diode.
 7. The apparatus of claim 1 furthercomprising a pliant substrate having the single fiber sensing elementattached thereto.
 8. The apparatus of claim 7 wherein the pliantsubstrate is attachable around at least a portion of the conduit.
 9. Theapparatus of claim 1 wherein the delay section is about 500 meters toabout 3000 meters long.
 10. The apparatus of claim 1 wherein themeasurement section is about 2 meters to about 10 meters long.
 11. Amethod for detecting an encoded pressure signal in a fluid flowing in aconduit comprising: generating an encoded pressure signal thatpropagates in a fluid flowing in a conduit; attaching an optical fibermeasurement element around at least a portion of the conduit, theoptical fiber measurement element having a reflector at a distal endthereof; splitting a first optical signal into a second optical signalpropagating in a first optical fiber, and a third optical signalpropagating in a second optical fiber having a delay section disposedtherein; directing the second optical signal and the third opticalsignal into the optical fiber measurement element to the reflector;reflecting the second optical signal and the third optical signal backthrough the second beam splitter/coupler such that at least a portion ofthe reflected second optical signal propagates through the secondoptical fiber and at least a portion of the third optical signalspropagates through the first optical; and detecting an interferencebetween the reflected second optical signal and the reflected thirdoptical signal and outputting a first signal related thereto.
 12. Themethod of claim 11 wherein the first signal is indicative of a timederivative of the encoded pressure signal in the conduit
 13. The methodof claim 12 further comprising integrating the first signal with respectto time and generating an output signal substantially similar to thefluid pressure signal in the conduit.
 14. The method of claim 13 furthercomprising decoding the output signal into data transmitted in the fluidpressure signal.
 15. The method of claim 11 further comprising attachingthe single fiber sensing element to a pliant substrate.
 16. The methodof claim 15 further comprising attaching the pliant substrate at leastpartially around the conduit.
 17. An apparatus for detecting an encodedfluid pressure pulse signal propagating in a conduit comprising: anoptical fiber measurement element disposed around at least a portion ofthe conduit, the optical fiber measurement element having a reflector ata distal end thereof; a light source injecting a first optical signalinto a first beam splitter/coupler to split the first optical signalinto a second optical signal propagating in a first optical fiber, and athird optical signal propagating in a second optical fiber; a delaysection disposed in the second optical fiber; a second beamsplitter/coupler to combine and direct the second optical signal and thethird optical signal into the optical fiber measurement element to thereflector, the reflector reflecting the second optical signal and thethird optical signal back through the second beam splitter/coupler suchthat at least a portion of the reflected second optical signalpropagates through the second optical fiber and at least a portion ofthe third optical signals propagates through the first optical fiber tothe first beam splitter/coupler; and an optical detector opticallycoupled to the first beam splitter/coupler to sense an interferencebetween the reflected second optical signal and the reflected thirdoptical signal and outputting a first signal related thereto.
 18. Theapparatus of claim 17 further comprising a controller to decode theoutput signal into data transmitted in the fluid pressure pulse signal.19. The apparatus of claim 17 wherein the optical fiber of the delaysection is about 500 meters to about 3000 meters long.
 20. The apparatusof claim 17 wherein the optical fiber of the measurement section isabout 2 meters to about 10 meters long.